International Petroleum Environmental Conference Oct. 30 – Nov. 1, 2017 San Antonio, Texas

REDUCING SULFUR DIOXIDE EMISSIONS DOWNSTREAM OF AMINE UNITS WITH DRY SORBENT INJECTION

Jonathan Byers, Spartan Energy Partners LPand Jon Norman, UCC Dry Sorbent Injection, LLC

Presented by:Colby Meyer, Spartan Energy Partners LP

Presentation Overview

Company Overview Why the Need for this Technology? Using DSI for SO2 Removal - System Overview Summary

COMPANY OVERVIEW

UCC Dry Sorbent Injection Overview

Dry Sorbent Injection (DSI) Experience for Air Pollution Control• Over 100 full-scale DSI tests and temporary systems• Almost 100 large, permanent systems total• Approximately one-half of the DSI systems used for SO2 reduction

UCC is a 97 year old global firm specializing in engineered material handling solutions for power and industrial customers

Spartan Energy Overview

Spartan Energy is a provider of natural gas treating and processing equipment and services globally

Spartan provides turnkey installation, commissioning, operations and maintenance services

EquipmentAmine Plants and Facilities Dehydration Units

Mechanical Refrigeration Units Cooling Units

Condensate Stabilizers JT Units

Natural Gas Compression Natural Gas Gensets

WHY THE NEED FOR THIS TECHNOLOGY?

Why the Need for this Technology?

Produced natural gas high in Hydrogen Sulfide (H2S) can create significant issues for operators

H2S is typically removed from produced natural gas streams using two methods– Scavenger: a liquid or solid media that removes H2S– Amine Treating: a regenerative solvent that removes H2S and CO2

Scavenger and Amine Treating each have their own benefits and disadvantages

The biggest issue with amine treating of high H2S gas is the disposal of H2S rich acid gas

Disposal of H2S

H2S emitted from Amine Unit

Regeneration System

Oxidation into SO2

(Flare or Thermal Oxidizer)

Acid Gas Injection Claus or Liquid Redox Process

H2S Disposal Considerations

H2S emitted from Amine Unit

Regeneration System

Oxidation into SO2

(Flare or Thermal Oxidizer)

Acid Gas Injection Claus or Liquid Redox Process

Capital Cost Low High Moderate to HighOperating Cost Low Moderate Moderate to LowRegulatory Burden Low to High Very High Moderate

DSI Used to Reduce Regulator Burden

Dry Sorbent Injection Overview

Dry Sorbent Injection is a process of injecting a sorbent into a waste gas stream to remove pollutants

It was commercialized over the last 25 years as a way for power plants to minimize SO2 and other pollutants

It is used extensively in power plants, waste incinerators, and other industrial processes

Spartan and UCC developed a modular DSI system that can be used in the oil and gas industry to reduce pollutant emissions downstream of an amine unit.

Spartan / UCC process is Patent Pending

Evolution of DSI

UCC developed test units for power plants to demonstrate DSI at power plants

The units are modular, trailer-mounted systems that are used to feed sorbent into power plant flue gas

With additional components that Spartan and UCC developed for amine systems, the DSI system can be set upon a site in a few weeks

Using DSI, SO2 pollution can be reduced by up to 90%

Production Limits at NSR Permit Threshold

-

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

- 1,000 2,000 3,000 4,000 5,000 6,000

Flow

Rat

e (m

msc

fd)

H2S PPM

Production Limits at NSR Permit Threshold

-

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

- 1,000 2,000 3,000 4,000 5,000 6,000

Flow

Rat

e (m

msc

fd)

H2S PPM

Production limitations Lead time Cost

Production Limits at NSRPermit Limit with DSI

-

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

- 1,000 2,000 3,000 4,000 5,000 6,000

Flow

Rat

e (m

msc

fd)

H2S PPM

Selection of a Sulfur Removal Technology

Selection of a Sulfur Removal Process requires evaluation of several variables– Concentration of H2S in produced gas– Concentration of CO2 in produced gas– Total gas flow and production curve– Anticipated life of production facilities and future drilling plans– Availability of existing infrastructure for treatment and disposal of

H2S– Operational/Complexity considerations

Traditional Sulfur Removal and Disposal

Solution Scavenger Liquid Redox Sulfur Recovery Unit

Acid Gas Injection

Summary Liquid or Solid media used to remove H2S from process gas

Removal of H2S using a reduction/oxidation reaction using a catalyst

Recovers H2S as elemental sulfur through the Claus Reaction

Injection of H2S and other acid gases into a non-producing formation to prevent emission into atmosphere

DSI

Sorbent injection to remove SO2 from an acid gas stream

All Options have Benefits and Drawbacks

Solution Scavenger DSI Liquid Redox Sulfur RecoveryUnit

Acid Gas Injection

Sulfur Removal “Sweet Spot”

<0.5 TPD 0.3-2 TPD <15 TPD >10 TPD High Volumes

High H2S in gas

Removal of CO2

Amine Required Amine Required Amine Required Amine Required Amine Required

Anticipated Life of Production

Short-Long Term

Short-Medium Term

Long Term Long Term Long Term

Availability of Existing Infrastructure

Limited InfrastructureNeeded

Temporary Equipment

New Facility New Facility Great if Available

Operational Complexity

Minimal Complexity

Minimal Complexity

Moderate Complexity

HighComplexity

High Complexity

Cost Considerations

Low Capital /High Variable

Low Capital/ ModerateVariable

ModerateCapital / Low Variable

High Capital / Low Variable

High Capital / Low Variable

USING DSI FOR SO2 REMOVAL

SO2 Removal – Sorbent Choice

Trona• Use when:

» Moderate SO2 removal needed (approx. 80% or less)

» Must be milled

» Optimum temperature is 275F to 1000F

Sodium Bicarbonate• Use when:

» High removals needed (> 80%)

» Want to minimize waste loading

» Optimum temperature is 275°F to 650°F

Hydrated Lime• Use when:

» Lower removals needed (<60%)

» Optimum temperature is 600 to 1100°F

» Highest usage/waste generation

SO2 Removal – Sorbent Comparison

30 40 50 60 70 80 90 100

Sorb

ent U

sage

% SO2 Removal

Relative Sorbent Usage vs. % Removal

SBC Trona Hydrated Lime

SYSTEM OVERVIEW

Description of Amine Process with DSI

Dry Sorbent Injection System

Silo and Blower/Mill Trailer

Semi-Mobile System, Sorbent Storage Silo

50 ton capacity (2000 ft3)

Blower/Mill Trailer

UCC VIPER® Mill(Two Sizes)

2 tph7 tph

Greatest opportunity for increased performance is to reduce particle size

• Increased surface area for reaction

• Increased number of particles/collisions

• Increased dispersion

UCC VIPER® Mill

Automated Cleaning System

Sorbent Inlet

Breather Tee

Discharge Diverter

ValveBearing Oil Lubrication

System

Support Base

Mill Drive Motor

Mill Skid

Cleaning System

Discharge

Sorbent Discharge

Milling TechnologyVIPER® Mill Skid Layout

VIPER® Mill

Unmilled Trona

25-40 µm 12-15 µm

Milled Trona

Unmilled SBC Milled SBC

150-180 µm 15-19 µm

DSI System Design

Splitters/Lances• Splitter design critical for performance and

reliability (auto purge system shown)• Lances designed for optimum dispersion

(COBRA™ Lances shown)

COBRA Lance

Filter Separator and Waste Handling

Collects spent sorbent byproduct directed into

two “dumpsters” using screw feeders

Byproduct disposal is non-hazardous

Installation - Equipment Arrival

Installation - Silo Preparation

Installation - Silo Set Up

SUMMARY

Factors to consider when choosing sulfur removal technology:

• CO2 and H2S amount in gas

• Gas flow and anticipated life of production facilities

• Existing infrastructure and operational/complexity considerations

Reducing SO2 emissions downstream of amine units with DSI

• Economical solution for applications ranging from 500-4000 lbs/day of sulfur, particularly when amine treating is also required.

• Mobile equipment allows for quick set-up and operation

• Enables higher gas production while maintaining permit limits

• Dry system – eliminates water and wastewater concerns

• Proven equipment

Summary

Questions?

For More Information

Jon Norman, PEManager, DSI Sales and Technology

UCC Dry Sorbent Injection, LLCP: 315-440-3244

jonnorman@unitedconveyor.com

Jonathan ByersVP, Corporate DevelopmentSpartan Energy Partners LP

P: 281-466-3313jon.byers@spartanep.com

Colby MeyerEngineer

Spartan Energy Partners LPP: 281-466-3317

colby.meyer@spartanep.com